1. Field of the Invention
This invention is directed to systems and methods for the recovery of fluid components from fluids used in wellbore operations. In certain particular embodiments this invention is directed to systems and methods for recovering base fluids from wellbore drilling and completion fluids, such base fluids including water and soluble additives, diesel, synthetic oils, mineral oils, brine, metal salt and other additives.
2. Description of Related Art
Fluids used in wellbore operations can be complex mixtures with various components present in precise amounts. In conventional rotary drilling, a borehole is advanced down from the surface of the earth (or bottom of the sea) by rotating a drill string having a drill bit at its lower end. Sections of hollow drill pipe are added to the top of the drill string, one at a time, as the borehole is advanced in increments. In its path downward, the drill bit may pass through a number of strata before the well reaches the desired depth. Each of these subsurface strata has associated with it physical parameters, e.g., fluid content, hardness, porosity, pressure, inclination, etc., which make the drilling process a constant challenge. Drilling through a stratum produces significant amounts of rubble and frictional heat; each of which must be removed if efficient drilling is to be maintained in typical rotary drilling operations, heat and rock chips are removed by the use of a fluid known as drilling fluid or drilling mud. Drilling mud is circulated down through the drill string, out through orifices in the drill bit where the mud picks up rock chips and heat, and returns up the annular space between the drill string and the borehole wall to the surface. The mud is, typically, sieved on the surface, reconstituted, and pumped back down the drill string.
Drilling mud may be as simple in composition as clear water, but more likely it is a complicated mixture of various components, e.g., but not limited to, clays, thickeners, and weighting agents. The characteristics of the drilled geologic strata and, to some extent, the nature of the drilling apparatus determine the physical parameters of the drilling fluid. For instance, the drilling mud must be capable of carrying the rock chips to the surface from the drilling site. Shale-like rocks often produce chips which are flat. Sandstones are not quite so likely to produce a flat chip. The drilling fluid must be capable of removing either type of chip. Conversely, the mud must have a viscosity which will permit it to be circulated at high rates without excessive mud pump pressures.
In the instance where a high pressure layer, e.g., a gas formation, is penetrated, the density of the drilling mud must be increased to the point such that the hydrostatic or hydraulic head of the mud is greater than the downhole (or "formation") pressure. This prevents gas leakage out into the annular space surrounding the drill pipe and lowers the chances for the phenomenon known as "blowout" in which the drilling mud is blown from the well by the formation gas. Finely ground barite (barium sulfate) is the additive most widely used to increase the specific gravity of drilling mud; although, in special circumstances, iron ore, lead sulfide ferrous oxide, or titanium dioxide may also be added.
In strata which are very porous or are naturally fractured and which have formation pressures comparatively lower than the local pressure of the drilling mud, another problem occurs. The drilling fluid, because of its higher hydrostatic head, will migrate out into the porous layer rather than completing its circuit to the surface. This phenomenon is known as "lost circulation." A common solution to this problem is to add a lost circulation additive such as gilsonite.
Fluid loss control additives may be included such as one containing either bentonite clay (which in turn contains sodium montmorillonite) or attapulgite, commonly known as salt gel. If these clays are added to the drilling mud in a proper manner, they will circulate down through the drill string, out the drill bit nozzles, and to the site on the borehole wall where liquid from the mud is migrating into the porous formation. Once there, the clays, which are microscopically plate-like in form, form a filter cake on the borehole wall. Polymeric fluid control agents are also well known. As long as the filter cake is intact, very liquid will be lost into the formation.
The properties required in drilling mud constantly vary as the borehole progresses downward into the earth. In addition to the various materials already noted, such substances as tannin-containing compounds (to decrease the mud's viscosity), walnut shells (to increase the lubricity of the mud between the drillstring and the borehole wall), colloidal dispersions, e.g., starch, gums, carboxy-methyl-cellulose (to decrease the tendency of the mud to form excessively thick filter cakes on the wall of the borehole), and caustic soda (to adjust the pH of the mud) are added as the need arises.
The fluid used as drilling mud is a complicated mixture tailored to do a number of highly specific jobs.
Once the hole is drilled to the desired depth, the well must be prepared for production. The drill string is removed from the borehole and the process of casing and cementing begins.
A well that is several thousand feet long may pass through several different hydrocarbon producing formations as well as a number of water producing formations. The borehole may penetrate sandy or other unstable strata. It is important that in the completion of a well each producing formation be isolated from each of the others as well as from fresh water formations and the surface. Proper completion of the well should stabilize the borehole for a long time. Zonal isolation and borehole stabilization are also necessary in other types of wells, e.g., storage wells, injection wells, geothermal wells, and water wells. This is typically done, no matter what the type of well, by installing metallic tubulars in the wellbore. These tubulars known as "casing," are often joined by threaded connections and cemented in place.
The process for cementing the casing in the wellbore is known as "primary cementing." In an oil or gas well, installation of casing begins after the drill string is "tripped" out of the well. The wellbore will still be filled with drilling mud. Assembly of the casing is begun by inserting a single piece of casing into the borehole until only a few feet remain above the surface. Another piece of casing is screwed onto the piece projecting from the hole and the resulting assembly is lowered into the hole until only a few feet remain above the surface. The process is repeated until the well is sufficiently filled with casing.
A movable plug, often having compliant wipers on its exterior, is then inserted into the top of the casing and a cement slurry is pumped into the casing behind the plug. The starting point for a number of well cements used in that slurry is Portland cement, the very same composition first patented by Joseph Aspdin, a builder from Leeds, England, in 1824. Portland cement contains Tricalcium silicate, Dicalcium silicate, Tricalcium aluminate, Tetracalcium aluminoferrite and other oxides. API Class A, B, C, G and H cements are all examples of Portland cements used in well applications. Neat cement slurries may be used in certain circumstances; however, if special physical parameters are required, a number of additions may be included in the slurry. As more cement is pumped in, the drilling fluid is displaced up the annular space between the casing and the borehole wall and out at the surface. When the movable plug reaches a point at or near the bottom of the casing, it is then ruptured and cement pumped through the plug and into the space between the casing and the borehole wall. Additional cement slurry is pumped into the casing with the intent that it displace the drilling mud in the annular space. When the cement cures, each producing formation should be permanently isolated thereby preventing fluid communication from one formation to another. The cemented casing may then be selectively perforated to produce fluids from particular strata.
However, the displacement of mud by the cement slurry from the annular space is rarely complete. This is true for a number of reasons. The first may be intuitively apparent. The borehole wall is not smooth but instead has many crevices and notches. Drilling mud will remain in those indentations as the cement slurry passes by. Furthermore, as noted above, clays may be added to the drilling mud to form filter cakes on porous formations. The fact that a cement slurry flows by the filter cake does not assure that the filter cake will be displaced by the slurry. The differential pressure existing between the borehole fluid and the formation will tend to keep the cake in place. Finally, because of the compositions of both the drilling mud and the cement slurry, the existence of non-Newtonian flow is to be expected. The drilling mud may additionally possess thixotropic properties, i.e., its gel strength increases when allowed to stand quietly and the gel strength then decreases when agitated.
The use of drilling fluids has improved drilling rates and reduced the amount of down-hole problems associated with drilling and completion fluids. The controlled removal of undesirable solids during the drilling and completion operations maintains fluid parameters in specification.
The prior art discloses a wide variety of systems and methods for cleaning wellbore fluids, removing undesirable components, separating fluid components, and for maintaining a desired mixture of fluid components.
U.S. Pat. No. 5,190,645 discloses a drilling mud system in which drilling mud is pumped by a pump into drill pipe and out through nozzles in a bit. The mud cools and cleans the cutters of the bit and then passes up through the well annulus flushing cuttings out with it. After the mud is removed from the well annulus, it is treated before being pumped back into the pipe. First, the mud enters a shale shaker where relatively large cuttings are removed. The mud then enters a degasser where gas can be removed if necessary. The degasser may be automatically turned on and off, as needed, in response to an electric or other suitable signal produced by a computer and communicated to the degasser. The computer produces the signal as a function of data from a sensor assembly associated with the shale shaker. The data from sensor assembly is communicated to the computer. The mud then passes to a desander (or a desilter), for removal or smaller solids picked up in the well. The mud next passes to a treating station where, if necessary, conditioning media, such as barite, may be added. Suitable flow controls control flow of media. Valves may be automatically operated by an electric or other suitable signal produced by the computer as a function of the data from sensor assembly, such signal being communicated to a valve. The mud is directed to a tank from which a pump takes suction, to be re-cycled through the well. The system may include additional treatment stations and centrifuges.
There has long been a problem with the handling and processing of hazardous waste material related to the operation of certain wellbore fluid systems and methods. There has long been a need for an efficient and effective wellbore fluid processing system and method. There has long been a need for a system and method for efficiently and effectively reclaiming fluid components and other components from a wellbore fluid mixture.